During drilling, pumping, and similar operations in reservoirs, such as oil and gas reservoirs, it is often useful to test or sample the reservoir fluid. In such testing or sampling, many problems can arise. It is important that the fluid tested or the sample retrieved is representative of the reservoir fluid. Further, information concerning many properties of the fluid must be obtained, and determination of one property may interfere with determination of another property. The various factors of importance in testing and sampling are often interrelated such that improving one factor degrades another. For example, operations such as drilling and pumping often need to be suspended during the testing and/or the properties need to be determined as close as possible to real time. However, wells are often deep, which increases the time and difficulty of making tests and taking samples. For sampling and testing while drilling, the drilling operation has to stop briefly so that sampling and testing can be carried out. It is highly desirable to reduce such stoppage. These factors often lead to maximizing the pumping speed to save time and related costs. However, the faster the pumping speed, the more likely that the phase of the fluid will change at some point along the pump path. FIG. 3 shows a well-known pressure-temperature (P-T) phase diagram. P1 indicates formation pressure, and P2 indicates pressure inside the pump. Assuming the change in fluid temperature to be negligible, P1 and P2 are on an isotherm, indicated by the arrow connecting P1 and P2. P2 has to be less than P1 for fluid to flow. In the region 77, the fluid is a liquid, while in the region 78, at least some of the liquid has changed to a gas. To maintain single phase, P2 has to be greater than the dew point line 79. However, if attention is only paid to maintaining efficient pumping speed, vapor can form in the system, in which case the test or sample is not representative of the reservoir fluid. In particular, bubbles begin to form at a temperature-pressure given by the bubble point line 80. On the other hand, slowing or stopping the pumping can result in contamination encroachment into the sample zone, which reduces the accuracy of the results and leads to even longer testing and sampling times. Thus, fluid control during drilling, pumping, and other reservoir operations can be difficult.
FIGS. 1 and 2 illustrate the difficulty of controlling fluid in a state-of-the-art downhole fluid sampling tool. FIG. 1 shows a display of a fluid control computer, such as shown at 284 in FIG. 5. Starting from left to right, the first track 12 shows the “formation pressure” (FPRE) at curve 15, which is the pressure as the fluid enters the tool. The text, such as 14, in track one shows the value of the formation pressure in psi (pounds per square inch). The second track 16 records Pump Performance, while the third track 18 displays Efficiency (not shown in the figure) and Time of Day. The fourth track 20 gives Pump Rate in cc/sec (cubic centimeters per second), and Raw Density is shown in the fifth track 23 (Fluid Density) at curve 22. The sixth track 26 is a volumetric bin display where the shadings indicate a range of fluid density in 0.1 g/cc ranges from 0.3 to 1.3 g/cc with the volume in percentage from left to right. This particular screen 10 shows a typical phase change that takes place in the pump as the pressure goes below the bubble point of the oil. The FPRE plot 14 shows FPRE going in steps from 1957 at 15:33 to a lower but varying pressure of 1300 to 1500 psi from 15:37 to 15:49. As the fluid cleans up from filtrate including contamination to formation oil, the density becomes more variable; and the Bin Display of track 26 shows some low volume gas and a change in three different fluid densities expelled from the pump, which fluid densities can be seen by the different shadings. In the actual display, these densities are shown in color, but because patent drawings do not yet allow color, the different densities are designated by different shading. The single phase is indicated by the shading at 33. The shading at 28 indicates one multi-phase density, the shading at 31 indicates another, and the shading at 32 indicates a third multi-phase density. At a high pump speed of 12 ccps, the formation pressure is low, for example, as at 14, and the density varies rapidly between different multiple phase densities. When the rate is reduced, the density goes back to a single phase as the FPRE pressure increases to 2102 psi. FIG. 2 shows a Bubble Point plot 50 of pressure versus pre-test fractional volume of the fluid sampled in the example of FIG. 1. As known in the art, the bubble point plot is generated downhole by decompressing the fluid in a pretest chamber and measuring the volume versus pressure relationship. Plot point 58 indicates the bubble point of the fluid to be 1525 psi. Beyond the bubble point, the curve gets very non-linear at 60 due to the development of the vapor phase. This is confirmed by FIG. 1, which shows multi phase behavior at 1500 psi and not at 2100 psi. Thus, the prior art system did not maintain the sand face pressure above the bubble point, and the sampling was not representative of the reservoir. Clearly, the state-of-the-art was not able to control the parameters of the sampling tool satisfactorily in this instance.
For the above reasons, it would be highly desirable to have a sampling/test tool that provides improved control of the sampling/test parameters.